Method of recovering energy from a fluid catalytic cracking unit for overall carbon dioxide reduction

ABSTRACT

In at least one embodiment of the present invention, a method of recovering energy from a FCC unit having a reactor and a regenerator for overall CO 2  reduction is provided. The method comprises cooling syngas to a predetermined low temperature to define cooled syngas. A turbo-expander including a first compressor is provided. The turbo-expander train is configured to combust and expand gas to drive the first compressor. The cooled syngas is compressed with the first compressor to define compressed syngas. A first stream of gas comprising CO 2  and a second stream of gas comprising CO are separated from the compressed syngas. O 2  and the first and second streams of gas are introduced to the turbo-expander train. The first stream of gas is expanded and the second stream of gas is combusted and expanded with the O 2  to recover energy, driving the first compressor and producing the syngas.

This application is the result of a joint research agreement between UOPLLC and BP Products North America Inc.

BACKGROUND OF THE INVENTION

The present invention relates to methods and systems of reducing carbondioxide emissions in a fluid catalytic cracking unit.

The fluidized catalytic cracking of hydrocarbons is the mainstay processfor the production of gasoline and light hydrocarbon products from heavyhydrocarbon charge stocks such as vacuum gas oils (VGO) or residualfeeds. Large hydrocarbon molecules associated with the heavy hydrocarbonfeed are cracked to break the large hydrocarbon chains thereby producinglighter hydrocarbons. These lighter hydrocarbons are recovered asproduct and can be used directly or further processed to raise theoctane barrel yield relative to the heavy hydrocarbon feed.

The basic equipment or apparatus for the fluidized catalytic cracking(FCC) of hydrocarbons has been in existence since the early 1940's. Thebasic components of the FCC process include a reactor, a regenerator,and a catalyst stripper. The reactor includes a contact zone where thehydrocarbon feed is contacted with a particulate catalyst and aseparation zone where product vapors from the cracking reaction areseparated from the catalyst. Further product separation takes place in acatalyst stripper that receives catalyst from the separation zone andremoves entrained hydrocarbons from the catalyst by counter-currentcontact with steam or another stripping medium.

The FCC process is carried out by contacting the startingmaterial—generally VGO, reduced crude, or another source of relativelyhigh boiling hydrocarbons—with a catalyst made up of a finely divided orparticulate solid material. The catalyst is transported like a fluid bypassing gas or vapor through it at sufficient velocity to produce adesired regime of fluid transport. Contact of the oil with the fluidizedmaterial catalyzes the cracking reaction. The cracking reaction depositscoke on the catalyst. Coke is comprised of hydrogen and carbon and caninclude other materials in trace quantities such as sulfur and metalsthat enter the process with the starting material. Coke interferes withthe catalytic activity of the catalyst by blocking active sites on thecatalyst surface where the cracking reactions take place. Catalyst istraditionally transferred from the stripper to a regenerator forpurposes of removing the coke by oxidation with an oxygen-containinggas. An inventory of catalyst having a reduced coke content relative tothe catalyst in the stripper, hereinafter referred to as regeneratedcatalyst, is collected for return to the reaction zone. Oxidizing thecoke from the catalyst surface releases a large amount of heat, aportion of which escapes the regenerator with gaseous products of cokeoxidation generally referred to as flue gas. The balance of the heatleaves the regenerator with the regenerated catalyst. The fluidizedcatalyst is continuously circulated from the reaction zone to theregeneration zone and then again to the reaction zone. The fluidizedcatalyst, as well as providing a catalytic function, acts as a vehiclefor the transfer of heat from zone to zone. Catalyst exiting thereaction zone is spoken of as being spent, i.e., partially deactivatedby the deposition of coke upon the catalyst. Specific details of thevarious contact zones, regeneration zones, and stripping zones alongwith arrangements for conveying the catalyst between the various zonesare well known to those skilled in the art.

Refining companies are under increased pressure to reduce carbon dioxideemissions as a result of carbon tax legislation and other drivers suchas a desire to demonstrate long-term sustainability. Thus, there is aneed to provide a way to reduce the carbon dioxide emissions of a fluidcatalytic cracking unit and from the refinery plant in general.

One solution to reducing carbon dioxide emissions involves operating theFCC regenerator at gasification conditions and supplying the regeneratorwith a feed comprising recycled carbon dioxide and oxygen. In thisscenario, carbon dioxide is reduced in part because the carbon dioxideis being recycled from a synthesis gas separator unit. One issue withthis solution, however, is that under gasification conditions, theregenerator may not supply enough energy to the FCC process for crackingthe hydrocarbon feedstock with the catalyst.

BRIEF SUMMARY OF THE INVENTION

Embodiments of the present invention generally provide methods andsystems of recovering energy from a fluid catalytic cracking unit havinga reactor and a regenerator for overall carbon dioxide reduction. Themethods and systems of the present invention provide solutions torecovering energy from a fluid catalytic cracking unit which may be usedto support the FCC process and/or to support other systems within therefinery which may lessen overall carbon dioxide emissions from therefinery.

In at least one embodiment of the present invention, a method ofrecovering energy from a fluid catalytic cracking unit having a reactorand a regenerator for overall carbon dioxide reduction is provided. Themethod comprises cooling syngas comprising carbon dioxide (CO₂), carbonmonoxide (CO), water (H₂O), hydrogen sulfide (H₂S) and carbonyl sulfide(COS) to a predetermined low temperature to define cooled syngas. Thesyngas is produced by the regenerator at gasification conditions. Aturbo-expander train including a first compressor is provided. Theturbo-expander train is configured to combust and expand gas to drivethe first compressor. The cooled syngas is compressed with the firstcompressor to a predetermined high pressure to define compressed syngas.A first stream of gas comprising CO₂ and a second stream of gascomprising CO are separated from the compressed syngas. Oxygen (O₂) andthe first and second streams of gas are introduced to the turbo-expandertrain. The first stream of gas is expanded and the second stream of gasis combusted and expanded with the O₂ to recover energy, driving thefirst compressor and producing feed gas comprising O₂ and CO₂.

In one aspect of the present invention, the method further comprises thefirst compressor having a compression ratio between about 5:1 and 10:1.The second stream of gas comprising at least one of CO and H₂ and thefeed gas comprises O₂ and at least one of CO₂ and H₂O. The feed gas isintroduced into the regenerator having spent catalyst from the reactor.At gasification conditions, the regenerator burns coke from the spentcatalyst, producing the syngas.

In at least one other embodiment of the present invention, a system forrecovering energy from a fluid catalytic cracking unit having a reactorand a regenerator for overall carbon dioxide reduction is provided. Thesystem comprises a cooling unit in fluid communication with theregenerator at gasification conditions. The regenerator produces syngascomprising CO₂, CO, H₂O, H₂S and COS. The cooling unit is configured tocool the syngas to a predetermined low temperature to define cooledsyngas. A turbo-expander train includes a first compressor in fluidcommunication with the cooling unit. The turbo-expander train isconfigured for receiving O₂, a first stream of gas comprising CO₂ and asecond stream of gas comprising CO. The turbo-expander train is furtherconfigured for expanding the first stream of gas and combusting andexpanding the second stream of gas with the O₂ to recover energy,driving the first compressor to compress the cooled syngas to apredetermined high pressure to define compressed syngas and producingfeed gas comprising O₂ and CO₂. In fluid communication with theturbo-expander is a separator unit. The separator unit is configured toseparate from the compressed syngas the first and second streams of gas.

Further objects, features and advantages of the invention will becomeapparent from consideration from the following description in theappended claims when taken in connection with the accompanying drawings.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 a is a schematic diagram of an example of a fluid catalyticcracking unit;

FIG. 1 b is a schematic diagram of a reactor and a regenerator of thefluid catalytic cracking unit of FIG. 1 a;

FIG. 2 a is a schematic diagram of a fluid catalytic cracking unit inaccordance with at least one embodiment of the present invention;

FIG. 2 b is a schematic diagram of a fluid catalytic cracking unit inaccordance with at least another embodiment of the present invention;

FIG. 2 c is a schematic diagram of a fluid catalytic cracking unit inaccordance with at least another embodiment of the present invention;

FIG. 2 d is a schematic diagram of a fluid catalytic cracking unit inaccordance with at least another embodiment of the present invention;and

FIG. 3 is a flow chart of an example of a method for recovering energyfrom a fluid catalytic cracking unit for overall CO₂ reduction inaccordance with the present invention.

DETAILED DESCRIPTION OF THE INVENTION

Detailed embodiments of the present invention are disclosed herein. Itis understood however, that the disclosed embodiments are merelyexemplary of the invention and may be embodied in various andalternative forms. The figures are not necessarily to scale; somefigures may be configured to show the details of a particular component.Therefore, specific structural and functional details disclosed hereinare not interpreted as limiting but merely as a representative basiswith the claims and for teaching one skilled in the art to practice thepresent invention.

Examples of the present invention seek to overcome some of the concernsassociated with heating a fluid catalytic cracking unit while reducingoverall CO₂ emissions from the refinery. A conventional fluid catalyticcracking unit burns coke from the spent catalyst by feeding gascomprising air and/or O₂ into the regenerator, producing flue gas, whichcontains CO₂ but is typically rich in nitrogen (N₂). However, byintroducing a feed gas comprising O₂ with CO₂ and/or H₂O into theregenerator, a synthesis gas (syngas) may be produced. Specifically, theCO₂ and the O₂ in the feed gas may react with the carbon-hydrogen basedcoke to produce CO₂, CO, H₂O and H₂ by a “dry” gasification process andthe H₂O and the O₂ in the feed gas may react with the coke to produceCO₂, CO and H₂ by a “wet” gasification process.

The H₂ in the syngas may be used as a raw material source for otheroperations within the refinery which may reduce the need for anadditional fuel source, such as a hydrogen furnace. Additionally, theCO₂ in the syngas may be more easily sequestered than CO₂ in N₂ richflue gas, such as for example, by limestone structures or any othersuitable means known to those skilled in the art. By reducing oreliminating the need for a hydrogen furnace and by sequestering the CO₂for recycling as a feed gas for operating the regenerator atgasification conditions, overall CO₂ emission may be reduced from therefinery.

However, burning coke on spent catalyst under gasification conditions isnot as exothermic a process as burning coke in air and/or O₂. Moreover,the coke fuel is typically limited because only about 4%, for example,of a VGO feedstock fed to the reactor is converted to coke which isdeposited upon the catalyst. Accordingly, less energy/heat is generatedunder gasification conditions and since the heat generated in theregenerator is used by the reactor for the cracking reaction, thereactor may be at a lower temperature which could adversely affectcracking of the hydrocarbon feedstock. Applicant has discovered that byseparating the syngas into two gas streams, a first gas streamcomprising CO₂ and a second gas stream comprising CO, variousembodiments may be provided for recovering energy from each of the gasstreams. The recovered energy may be used to support production ofsyngas processing and/or supplying the regenerator with a heated feedgas to provide more available heat for operating the reactor at reactiontemperatures and/or generating electrical power and/or supporting othersystems within the refinery with H₂ requirements.

Referring now to the drawings, FIG. 1 a illustrates a fluid catalyticcracking (FCC) unit and separation system 10. As shown, the FCC unit 10comprises a reactor 12 that is configured to receive a crude orhydrocarbon feedstock 30 (fresh feed) and a regenerator 14 in fluidcommunication with the reactor 12 to receive spent catalyst. The reactor12 cracks the feedstock 30 therein to an effluent containinghydrocarbons ranging from methane through relatively high boiling pointmaterials along with H₂ and H₂S. During the cracking reaction, acarbonaceous by-product is deposited on the circulating catalyst. Thismaterial, termed “coke,” is continuously burned off the spent catalystin the regenerator 14 as will be mentioned below.

The FCC unit 10 comprises the regenerator 14 for regenerating spentcatalyst from the reactor 12. The regenerator 14 is configured toreceive a feed gas 22 from an outside source and spent catalyst from thereactor 12. From the reactor 12, the spent catalyst has coke depositedthereon, reducing the activity of the catalyst. The regenerator 14receives the feed gas 22 to burn the coke off the spent catalyst,thereby producing a flue gas 26 that exits a flue gas line 28 to aflue-gas system. The flue gas 26 may comprise CO, CO₂, H₂O (steam),SO_(x) and N₂, but it is typically very rich in N₂ The regenerator 14 isconfigured to rejuvenate or reactivate the spent catalyst by burning thedeposited coke off the spent catalyst with the feed gas 22.

The regenerator 14 reactivates the catalyst so that, when returned tothe reactor 12, the catalyst is in optimum condition to perform itscracking function. The regenerator 14 serves to gasify the coke from thecatalyst particles and, at the same time, to impart sensible heat to thecirculating catalyst. The energy carried by the hot regenerator catalystis used to satisfy the thermal requirements for the reactor 12 of theFCC unit 10.

It is to be noted that the FCC unit 10 may have a number of optionalunits associated with the flue-gas system. In one embodiment, the fluegas 26 may comprise catalyst fines, N₂ from air used for combustion,products of coke combustions (e.g., oxides of carbon, sulfur, nitrogen,and water vapor), and trace quantities of other compounds. The flue gas26 exits the regenerator 14 at a temperature of approximately 1325degrees Fahrenheit (F), but may be as high as 1400 degrees F. or as lowas 1200 degrees F., and at pressures of between about 20 and 50 poundsper square inch gauge (psig). The thermal and kinetic energy of the fluegas 26 can be converted to steam or used to drive a turbo-expandergenerator system for electrical power generation. Unconverted CO in theflue gas 26 can be combusted to CO₂ in a CO boiler with production ofhigh-pressure steam. Catalyst fines may be removed by a solid removalunit, such as for example, an electrostatic precipitator. CO₂ from theregenerator and/or CO boiler is released to the atmosphere.

Referring now to FIGS. 1 a to 1 b, from the regenerator 14, hotregenerated catalyst is fed back to the reactor 12 via reactivatedcatalyst return line 20 and vaporizes the hydrocarbon feedstock 30 todefine resultant vapors. The resultant vapors carry the catalyst upwardthrough a riser 16 of the reactor 12 with a minimum of back mixing. Atthe top of the riser 16, desired cracking reactions have been completedand the catalyst is quickly separated from the hydrocarbon vapors tominimize secondary reactions. The catalyst-hydrocarbon mixture from theriser 16 is discharged into the reactor 12 vessel through a separationdevice 18, e.g., a riser termination device, achieving a substantialdegree of catalyst-gas separation, e.g., at least 90 weight percentproduct vapor separation from catalyst. A final separation of catalystand product vapor may be accomplished by cyclone separation.

The reactor effluent is directed to a main fractionator or fractionationcolumn 50 of the unit 10 for resolution into gaseous light olefinco-products, FCC gasoline, and cycle stocks. The spent catalyst dropsfrom within the reactor 12 vessel into a stripping section 24 thereof,where a countercurrent flow of steam removes interstitial and someadsorbed hydrocarbon vapors, defining stripped spent catalyst. Strippedspent catalyst descends through a first standpipe 23 and into theregenerator 14.

To maintain the activity of the working-catalyst inventory at a desiredlevel and to make-up for any catalyst lost from the system with the fluegas 26, fresh catalyst may be introduced into the circulating-catalystsystem by any suitable manner. For example, this may be accomplished byway of a catalyst storage hopper (not shown). Moreover, an additionalstorage hopper (not shown) may be used to hold spent catalyst withdrawnfrom the circulating system as necessary to maintain the desired workingactivity and to hold all catalyst inventory when the FCC unit 10 is shutdown for maintenance and repairs.

As shown in FIGS. 1 a and 1 b, in the operation of the FCC unit 10,fresh feedstock 30 and (depending on product-distribution objectives)recycled cycle oils are introduced into the bottom of the riser 16together with a controlled amount of regenerated catalyst. The chargemay be preheated, either by heat exchange or, for some applications, bymeans of a fired heater.

Feedstocks 30 for the FCC process include mixtures of hydrocarbons ofvarious types, including relatively small molecules such as found ingasoline to large molecules of 60 or more carbon atoms. The feedstock 30may include a relatively small content of contaminant materials such asorganic sulfur, nitrogen compounds, and organometallic compounds. It isto be noted that the relative proportions of all such materials willvary with the geographic origin of the crude and the particular boilingrange of the FCC feedstock 30. However, the feedstocks 30 may be rankedin terms of their “crackabilities,” or the ease with which they can beconverted in an FCC unit. Crackability may be defined by a function ofthe relative proportions of paraffinic, naphthenic, and aromatic speciesin the feed.

The FCC unit 10 further includes a main-fractionation column 50 throughwhich the reactor effluent is separated into various products. Themain-fractionation comprises an overhead line 52, a first side cut line54, a second side line 56, a third side cut line 58, and a bottom line60. As shown, the overhead line 52 includes gasoline and lightermaterial, the first side cut line 54 includes naphtha, the second sidecut line 56 includes light cycle oil, the third side cut line 58includes heavy cycle oil, and the bottom line 60 includes slurry oil.The lines may include other products without falling beyond the scope orspirit of the present invention.

Reactor-product vapors are directed to the main fractionator 50 at whichgasoline and gaseous olefin-rich co-products are taken overhead androuted to a gas-concentration unit 70. At the main-fractionator 50,light-cycle oil is recovered as a side cut with the net yield of thismaterial being stripped for removal of light ends and sent to storage.Net column bottoms are yielded as slurry or clarified oil. Because ofthe high efficiency of the catalyst-hydrocarbon separation systemutilized in the reactor design, catalyst carry-over to the fractionator50 is minimized and it is not necessary to clarify the net heavy productyielded from the bottom of the fractionator 50 unless the material is tobe used in some specific application requiring low solids content suchas the production of carbon black. In some instances, heavy material canbe recycled to the reactor riser 16.

Maximum usage is made of the heat available at the main column 50.Typically, light-cycle and heavy-cycle oils are utilized in thegas-concentration section 70 for heat-exchange purposes, and steam isgenerated by circulating main-column bottoms stream.

The gas-concentration column 70 is in fluid communication with overheadline of the main-fractionation column 50. From the overhead line 52, thegas-concentration column 50 receives unstable gasoline and lighterproducts that are separated therethrough into fuel gas for alkylation,polymerization, and debutanized gasoline.

The gas-concentration section 70 may be one or an assembly of absorbersand fractionators that separate the main-column overhead into gasolineand other desired light products. Olefinic gases from other processessuch as coking may be also sent to the FCC gas-concentration section.The gas-concentration unit may have one or a plurality of columns. Forexample, the gas-concentration unit may be a “four-column”gas-concentration plant comprising a primary absorber, a secondaryabsorber, a stripper, and a debutanizer.

Referring now to FIGS. 2 a-2 d, at least one embodiment of a system 80for recovering energy from a fluid catalytic cracking unit having areactor 12 and a regenerator 14 for overall CO₂ reduction is provided.The system 80 comprises a cooling unit 116 that is in fluidcommunication with the regenerator 14 at gasification conditions. Theregenerator produces syngas 84 that comprises CO₂, CO, H₂O (steam), H₂Sand COS. The syngas 84 may also further include H₂. The cooling unit 116is configured to cool the syngas 84 to a predetermined low temperatureto define cooled syngas. In one example, the cooling unit 116 cools thesyngas 84 from a temperature between about 1200 and 1850 degrees F. to atemperature between about 200 and 600 degrees F. The cooling unit 116may be, for example, a boiler that extracts energy from the coolingsyngas 84 to produce steam. Moreover, by cooling the syngas 84preferably between a temperature of about 200 and 400 degrees F. or evenlower, the H₂O in the syngas 84 may be condensed within the syngas 84,which may facilitate subsequent processing of compressing the syngas 84.

A turbo-expander train 110 includes a first compressor 82. The firstcompressor 82 is in fluid communication with the cooling unit 116. Thecompressor 82 is for compressing the cooled syngas 84 at an inletpressure to a predetermined high pressure to define a compressed syngas85. In one example, the compressor 82 has a compression ratio betweenabout 5:1 and 10:1 and preferably has a compression ratio of about 7:1.The inlet pressure may be, for example, between about 25 and 35 psig.The first compressor 82 preferably compresses the cooled syngas 84 to apressure between about 150 and 500 psig.

Moreover, in the example where the syngas 84 is cooled to a temperaturethat condenses the H₂O in the syngas 84, compression of the cooledsyngas 84 is facilitated because the cooled syngas 84 volume is reducedwhich therefore reduces the horsepower required by the first compressor82 for compression. Also, the steam that may be generated by the coolingunit/boiler 116 may be used to recover energy, for example, by a steamturbine (not shown) which may or may not be operatively coupled to theturbo-expander train 110. In the scenario where the steam turbine isoperatively coupled to the turbo-expander train, the steam turbine helpsdrive the first compressor 82.

A separator unit 86 is in fluid communication with the first compressor82 and is configured to separate from the compressed syngas 85, a firststream of gas 88 comprising CO₂ and a second stream of gas 96 comprisingCO. In one example, the first stream of gas 88 contains substantiallyonly CO₂ and the second stream of gas 96 may contain substantially onlyCO or at least one of CO and H₂. The separator unit 86 may includeseveral other sub-units for separating. In one example, the separateunit 86 is further configured to separate H₂S from the compressed syngas85 prior to the separator unit 86 producing the first and second streamsof gas 88 and 96. In this scenario, the separator unit may use a wet gasscrubbing process such as amine absorption, Rectisol™, or Selexol™,which is used to remove H₂S, COS, and the CO₂ from the compressed syngas85 to form the first and second streams of gas 88 and 96. The syngas gas85 may also contain CO and H₂, which can be mixed with steam and sent toa water-gas shift reactor to convert CO to CO₂, thus producingadditional H₂. The H₂ may be further separated from the CO₂ via aprocess known as pressure swing adsorption. In this scenario, theseparated H₂ 72 may minimize the need to burn hydrocarbon fuelselsewhere in the plant for use by another system, thereby reducingoverall CO₂ emissions from the refinery. For example, the separated H₂72 may be used by another system by being burned as a fuel or used tohydro-treat or hydrocrack other hydrocarbons. Other suitable units orsystems for separating known to those skilled in the art may also beused.

Heat recovery and cooling by a cooling unit 90 may be performedsubsequent to compressing the syngas 84 by the compressor 82 but priorto the compressed syngas 85 being processed by the separation unit 86.In one example, the cooling unit 90 cools the compressed syngas 85 froma temperature between about 600 and 800 degrees F. to between about 300and 500 degrees F.

The turbo-expander train 110 may further include a first expander 100, ashaft 112, and a combustion zone 92. The shaft 112 is operativelycoupled to both the first expander 100 and the first compressor 82 suchthat the first expander 100 rotates the shaft 112 which drives the firstcompressor 82. The combustion zone 92 is in fluid communication with thefirst expander 100.

The combustion zone 92 is configured to receive the second stream of gas96 and a stream of O₂ 104 to produce heated gas. In one embodiment andas illustrated in FIGS. 2 c and 2 d, the combustion zone 92 may receivethe second stream of gas 96 and the O₂ 104 directly. Alternatively andas illustrated in FIGS. 2 a and 2 d, the O₂ 104 may be combined with thefirst stream of gas 104 and/or may be further compressed by a secondcompressor 96 of the turbo-expander train 110 prior to being received bythe combustion zone 92. The second compressor 96 in this scenario isoperatively coupled to the shaft 112 and may also be driven by the firstexpander 100.

The combustion zone 92 is configured for combusting the second stream ofgas 96 with the O₂ 104 to a predetermined high temperature to produceheated gas 98. In one example, the predetermined high temperature isbetween about 1800 and 2100 degrees F. The combustion zone 92 combuststhe CO and any H₂ (if present) from the second stream of gas 96 with theO₂ 104 to produce the heated gas 98 comprising CO₂ and/or H₂O. Moreover,some of the O₂ may remain un-reacted, especially if the O₂ isstoichiometrically in excess to the second stream 96. In this scenario,the excess O₂ also forms a portion of the heated gas 98.

The first expander 100 is configured to extract energy from the heatedgas 98 by expanding the heated gas 98 to a predetermined low pressure,producing a feed gas 102 for the regenerator 14. In one example, thefeed gas 102 comprises O₂ and CO₂ and may also contain H₂O. The feed gas102 preferably has a pressure between about 30 and 70 psig and atemperature between about 1200 and 2100 degrees F. The first expanderalso uses the extracted energy to rotate the shaft 112. In oneembodiment, the expander 100 is a 10 to 15 stage turbo-expander.

The feed gas 102 may then be introduced into the regenerator 14. Theregenerator 14 is operating at gasification conditions to burn coke fromspent catalyst from the reactor 12 to produce the syngas 84. The hotterthe feed gas 102, the greater the total heat available (THA) in theregenerator 14 which is then used by the reactor 12 for cracking thefeedstock 30 at reaction temperatures. In the scenario where the feedgas 102 has a temperature between about 1200 F and 2100 F, the O₂ levelin the feed gas 102 may be proportioned correspondingly to the level ofcoke deposited on the spent catalyst to provide the reactor with atleast about 600 BTU per pound of feedstock 30. For example, the lowerthe coke content on the spent catalyst, the higher the proportion of O₂in the feed gas 102 and vice versa. The at least about 600 BTU per poundof feedstock may provide the reactor 12 with enough heat to operate atreaction temperatures for cracking the feedstock 30.

In one embodiment, the first stream of gas 88 has a temperature of aboutat least 90 degrees F. and a pressure of at least about 100 psig andpreferably at least about 180 psig. Accordingly, the first stream of gas88, being highly compressed, has significant stored energy. Theturbo-expander train 110 has several embodiments that extract energyfrom the first stream of gas 88 by expanding the gas 88. As illustratedin FIG. 2 a, the first stream of gas 88 may be combined with the streamof O₂ 104 and fed to the combustion zone 92 with the second stream ofgas 96. The first stream of gas 88 thereby becomes further heated by thecombustion of the second stream of gas 96 with the O₂ and becomes partof the heated gas 98. As should be noted, the first stream of gas 88,being comprised substantially of CO₂, does not combust with the O₂ inthe combustion zone 92. The expander 100, as discussed in the foregoingparagraphs, extracts energy by expanding the heated gas 98, which inthis example includes the heated first stream of gas 88.

Alternatively and as illustrated in FIG. 2 c, the first stream of gas 88may be combined with the heated gas 98 and then fed to the firstexpander which extracts energy by expanding both the heated gas 98 andthe first stream of gas 88. Once expanded, the first stream of gas 88makes up a portion of the feed gas 102.

In yet another embodiment and as illustrated in FIG. 2 b, the firststream of gas 88 may be further compressed by the second compressor 94and then fed to the combustion zone 92 with the second stream of gas 96and the O₂ 104. The first stream of gas 88, now being heated, makes up aportion of the heated gas 98.

In still yet another embodiment and as illustrated in 2 d, theturbo-expander train 110 may further include a second expander 120operatively coupled to the shaft 112 such that the first and secondexpanders 100 and 120 cooperatively rotate the shaft 112. The firststream of gas 88 may be fed to the second expander 120 which extractsenergy by expanding the first stream of gas 88. The second expander 120uses the extracted energy to rotate the shaft 112. The expanded firststream of gas 88 may then be combined with the feed gas 102 streamexiting the first expander 100, forming a portion of the feed gas 102received by the regenerator 14.

The system 80 may include a solid removal unit 114. The cooling unit 116is in fluid communication with the solid removal unit 114 and the firstcompressor 82. The solid removal unit 114 is in fluid communication withthe regenerator 14 and may be used to remove catalyst fines from thesyngas 84 prior to the syngas 84 being received by the cooling unit 116and/or the compressor 82.

In at least one other embodiment, the turbo-expander train 110 furtherincludes a motor generator 118. The motor generator 118 is operablycoupled to the shaft 112 and may be driven by the expander 100 or may beused to assist rotation of the shaft 112. In one example, the motorgenerator 118 produces electrical power when the shaft 112 is rotated.The electrical power may be used for various processes within the plant.The generated electrical power minimizes the need to burn fuel elsewherein the plant for power, thereby reducing overall CO₂ emissions from theplant.

Referring to FIG. 3, a method for recovering energy from a fluidcatalytic cracking unit having a reactor and a regenerator with reducedCO₂ emissions is provided. The method comprises cooling syngas 130 to apredetermined low temperature to define cooled syngas. The syngas isproduced by the regenerator at gasification conditions. In one example,the cooled syngas has a temperature between about 200 and 600 degrees F.

A turbo-expander train is provided 132. The turbo-expander trainincludes a first compressor. The turbo-expander train is configured tocombust and expand gas streams to drive the first compressor.

The cooled syngas is compressed 134 with the first compressor to apredetermined high pressure to define compressed syngas. In one example,the cooled syngas is at an inlet pressure between about 25 and 35 psigand the predetermined high pressure is between about 150 and 500 psig.

A first stream of gas comprising CO₂ and a second stream of gascomprising CO are separated from the compressed syngas 136. The secondstream of gas may also contain H₂.

O₂ and the first and second streams of gas are introduced to theturbo-expander train 138. The turbo-expander train expands the firststream of gas and combusts and expands the second stream of gas with theO₂ to recover energy, driving the first compressor and producing feedgas.

As a person skilled in the art will readily appreciate, the abovedescription is meant as an illustration of the implementation of theprinciples of the invention. This description is not intended to limitthe scope or application of this invention in that the invention issusceptible to modification, variation and change without departing fromthe spirit of this invention, as defined in the following claims.

1. A method of recovering energy from a fluid catalytic cracking unithaving a reactor and a regenerator for overall carbon dioxide reduction,the method comprising: cooling syngas comprising CO₂, CO, H₂O, H₂S andCOS to a predetermined low temperature to define cooled syngas, thesyngas produced by the regenerator at gasification conditions; providinga turbo-expander train including a first compressor, the turbo-expandertrain being configured to combust and expand gas to drive the firstcompressor; compressing the cooled syngas with the first compressor to apredetermined high pressure to define compressed syngas; separating fromthe compressed syngas a first stream of gas comprising CO₂ and a secondstream of gas comprising CO; and introducing O₂ and the first and secondstreams of gas to the turbo-expander train including expanding the firststream of gas and combusting and expanding the second stream of gas withthe O₂ to recover energy, driving the first compressor and producingfeed gas comprising O₂ and CO₂.
 2. The method according to claim 1wherein the predetermined low temperature is between about 200 and 600degrees Fahrenheit (F).
 3. The method according to claim 1 wherein thepredetermined high pressure is between about 150 and 500 psig.
 4. Themethod according to claim 1 further comprising introducing the feed gasinto the regenerator having spent catalyst from the reactor, theregenerator at gasification conditions to burn coke from the spentcatalyst, producing the syngas.
 5. The method according to claim 4wherein the feed gas has a temperature between about 1200 and 2100degrees Fahrenheit (F) and a pressure between about 30 and 70 psig. 6.The method according to claim 1 wherein the syngas further comprises H₂and the method further comprises separating at least a portion of the H₂from the compressed syngas, the portion of the H₂ being used for anothersystem, reducing overall CO₂ emissions.
 7. The method according to claim1 wherein the syngas further comprises H₂ and the second stream of gasfurther comprises H₂.
 8. The method according to claim 1 wherein theturbo-expander train further includes a first expander, a shaftoperatively coupled to both the first expander and the first compressorsuch that the first expander rotates the shaft which drives the firstcompressor, and a combustion zone in fluid communication with the firstexpander and the step of combusting and expanding the second stream ofgas with O₂ includes introducing the second stream of gas and the O₂ tothe combustion zone to produce heated gas, and extracting energy fromthe heated gas by the first expander, producing at least a portion ofthe feed gas and driving the first expander to rotate the shaft.
 9. Themethod according to claim 8 wherein step of expanding the first streamof gas includes introducing the first stream of gas with the heated gasto the first expander, and extracting energy from the first stream ofgas by the first expander, producing at least a portion of the feed gasand driving the first expander to rotate the shaft.
 10. The methodaccording to claim 9 wherein the step of expanding the first stream ofgas further includes introducing the first stream of gas into thecombustion zone with the second stream of gas and the O₂, heating thefirst stream of gas.
 11. The method according to claim 10 wherein theturbo-expander train further includes a second compressor in fluidcommunication with the combustion zone and operatively coupled to theshaft such that rotation of the shaft drives the second compressor, andthe step of expanding the first stream of gas further includesintroducing the first stream of gas with the O₂ into the secondcompressor, compressing the first stream of gas and the O₂.
 12. Themethod according to claim 8 wherein the turbo-expander train furtherincluding a second expander operatively coupled to the shaft such thatthe first and second expanders cooperatively rotate the shaft and thestep of expanding the first stream of gas includes extracting energyfrom the first stream of gas by the second expander, producing at leasta portion of the feed gas and driving the second expander to rotate theshaft.
 13. The method according to claim 8 wherein the turbo-expandertrain further includes a motor generator operatively coupled to theshaft such that rotation of the shaft drives the motor generator, andthe step of introducing O₂ and the first and second streams of gas tothe turbo-expander train further includes driving the motor generator,producing electrical energy.
 14. A method of recovering energy from afluid catalytic cracking unit having a reactor and a regenerator foroverall carbon dioxide reduction, the method comprising: cooling syngascomprising CO₂, CO, H₂O, H₂S and COS to a predetermined low temperatureto define cooled syngas; providing a turbo-expander train including acompressor, the turbo-expander train being configured to combust andexpand gas to drive the compressor, the compressor having a compressionratio between about 5:1 and 10:1; compressing the cooled syngas with thecompressor to a predetermined high pressure to define compressed syngas;separating from the compressed syngas a first stream of gas comprisingCO₂ and a second stream of gas comprising at least one of CO and H₂;introducing O₂ and the first and second streams of gas to theturbo-expander train including expanding the first stream of gas andcombusting and expanding the second stream of gas with the O₂ to recoverenergy, driving the compressor and producing feed gas comprising O₂ andat least one of CO₂ and H₂O; and introducing the feed gas into theregenerator having spent catalyst from the reactor, the regenerator atgasification conditions to burn coke from the spent catalyst, producingthe syngas.
 15. The method according to claim 14 further comprisingremoving catalyst fines from the syngas.
 16. The method according toclaim 14 further comprising removing at least a portion of H₂S from thecompressed syngas.
 17. The method according to claim 14 furthercomprising cooling the compressed syngas to a temperature between about300 and 500 degrees Fahrenheit (F) prior to the step of separating.